ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwire - Feb. 7, 2013) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS) achieved net earnings attributable to common equity shareholders of $315 million, or $1.66 per common share, for 2012 compared to $311 million, or $1.71 per common share, for 2011.

"Our Canadian regulated utilities, led by strong growth at FortisAlberta, achieved approximately 11% growth in earnings year over year," says Stan Marshall, President and Chief Executive Officer, Fortis Inc.

Earnings in 2012 were reduced by $7.5 million as a result of expenses related to the CH Energy Group, Inc. ("CH Energy Group") acquisition, while earnings in 2011 were favourably impacted by $11 million as a result of a merger termination fee paid to Fortis. Excluding these items, earnings to common equity shareholders were $322.5 million, or $1.70 per common share, for 2012 up $22.5 million from $300 million, or $1.65 per common share, for 2011, driven by improved performance at the Canadian Regulated Utilities, partially offset by higher corporate expenses. A 5% increase in the weighted average number of common shares outstanding year over year, largely associated with the issuance of common equity in mid-2011, had the impact of lowering earnings per common share in 2012.

Fortis increased its quarterly common share dividend to 31 cents from 30 cents, commencing with the first quarter dividend payable on March 1, 2013, which translates into an annualized dividend of $1.24. Fortis has raised its annualized dividend to common shareholders for 40 consecutive years, the record for a public corporation in Canada. The dividend payout ratio was 72% in 2012.

"For the fourth consecutive year, our capital program surpassed $1 billion," says Marshall. "Fortis utilities collectively serve more than two million customers and our capital program, the majority of which is occurring in western Canada, will ensure we continue to meet the growing energy needs of our existing and new customers," he explains.

Fortis announced in February 2012 that it had entered into an agreement to acquire CH Energy Group for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. CH Energy Group's main business, Central Hudson Gas & Electric Corporation ("Central Hudson"), serves 375,000 electric and gas customers in New York State's Mid-Hudson River Valley. Central Hudson's capital program over the next five years is expected to average more than $125 million annually.

Approval by the New York State Public Service Commission ("NYSPSC") of the Corporation's acquisition of CH Energy Group is the last significant regulatory matter required to close the transaction. A Settlement Agreement, among Fortis, CH Energy Group, NYSPSC staff, registered interveners and other parties, was filed with the NYSPSC in January 2013. The acquisition of CH Energy Group is anticipated to close during the second quarter of 2013. It is expected to be accretive to earnings per common share of Fortis within the first full year of ownership, excluding acquisition-related expenses.

"With the acquisition of CH Energy Group, the Corporation's regulated midyear rate base will increase to approximately $10 billion," says Marshall. "The regulated assets and earnings of Fortis will be further diversified by geographic location and regulatory jurisdiction, thereby helping to reduce business risk," he adds.

Capital expenditures were $1.13 billion for the year. At FortisBC Gas, the Customer Care Enhancement Project came into service at the beginning of 2012. The largest capital project currently underway, the non-regulated $900 million, 335-megawatt Waneta Expansion hydroelectric generating facility ("Waneta Expansion") on the Pend d'Oreille River in British Columbia, continues on time and on budget. Excavation of the intake, powerhouse and power tunnels was completed during the year. Approximately $436 million in total has been spent on the Waneta Expansion since construction began in late 2010, with a further $227 million expected to be spent in 2013. Fortis owns 51% of the Waneta Expansion and will operate and maintain the facility when it comes online, expected spring 2015.

Canadian Regulated Utilities contributed earnings of $345 million, $34 million higher than earnings of $311 million for 2011.

Canadian Regulated Electric Utilities contributed earnings of $207 million, up $33 million from 2011. FortisAlberta's earnings increased $22 million, mainly related to growth in energy infrastructure investment, net transmission revenue of $8.5 million recognized in 2012, and lower-than-expected depreciation expense and finance charges in 2012, partially offset by a $1 million gain on sale of property in 2011. FortisAlberta invested more than $400 million in capital projects in 2012 and is expected to invest a comparable amount in 2013. Newfoundland Power's earnings were $5 million higher year over year, largely due to lower effective income taxes. FortisBC Electric's earnings increased $2 million as a result of growth in energy infrastructure investment, higher pole-attachment revenue, and lower-than-expected finance charges in 2012, partially offset by the discontinuance of the performance-based rate-setting ("PBR") mechanism on December 31, 2011. Improved earnings of $4 million at Other Canadian Regulated Electric Utilities were mainly due to lower effective income taxes at Maritime Electric and cumulative return earned on capital investment in smart meters at FortisOntario.

FortisBC Electric's offer to purchase the City of Kelowna's electrical utility assets for approximately $55 million, which is subject to satisfaction of certain conditions and receipt of applicable approvals, including regulatory approval, is expected to close by the end of the first quarter of 2013. FortisBC Electric has operated and maintained the assets, which currently serve some 15,000 customers, since 2000.

Canadian Regulated Gas Utilities delivered earnings of $138 million, up $1 million from 2011. Growth in energy infrastructure investment, higher gas transportation volumes to industrial customers, lower-than-expected operating expenses in 2012 and lower effective income taxes were partially offset by lower-than-expected customer additions in 2012 and lower capitalized allowance for funds used during construction ("AFUDC").

"The regulatory calendar at our Canadian utilities was very busy in 2012 and remains so for 2013," says Marshall. "We expect continued regulatory stability, notwithstanding the significant proceedings in 2013," he adds.

FortisBC received regulatory decisions in 2012 for 2012/2013 revenue requirements at its gas and electric utilities and expects to file its next rate applications in the first half of 2013. A regulatory decision on a request by FortisBC Gas to amalgamate its three gas utilities into one legal entity and to implement common rates and services for customers across British Columbia, effective January 1, 2014, is pending. FortisAlberta received a decision in April 2012 for its 2012 revenue requirements. The Alberta Utilities Commission ("AUC") issued a generic decision in September 2012 on its PBR Initiative, outlining the PBR framework applicable to distribution utilities in Alberta for a five-year term, which commenced January 1, 2013. The Alberta PBR decision raises concerns and uncertainty for FortisAlberta regarding the treatment of certain capital expenditures. FortisAlberta, along with other distribution utilities operating in Alberta, have sought clarification of this matter in applications filed in November 2012 and have also requested leave to appeal the PBR decision to the Alberta Court of Appeal. Final allowed rates of return on common shareholder's equity and capital structure for 2013 remain outstanding for FortisBC, FortisAlberta and Newfoundland Power. In Alberta, a Generic Cost of Capital ("GCOC") Proceeding was initiated by the AUC in October 2012. In British Columbia, a public hearing occurred in December 2012 related to the first phase of a GCOC Proceeding initiated by the regulator in 2012. At Newfoundland Power, a public hearing commenced in January 2013 related to the utility's general rate application filed in September 2012 to set 2013/2014 customer rates and cost of capital.

Caribbean Regulated Electric Utilities contributed $19 million of earnings compared to $20 million for 2011. FortisTCI Limited acquired Turks and Caicos Utilities Limited ("TCU") in August 2012 for an aggregate purchase price of approximately $13 million (US$13 million), inclusive of debt assumed. TCU serves more than 2,000 customers on Grand Turk and Salt Cay. The utility currently operates pursuant to a 50-year licence that expires in 2036.

Non-Regulated Fortis Generation contributed $17 million to earnings compared to $18 million for 2011. The decrease in earnings was mainly due to overall lower production associated with less rainfall and a generating facility being out of service in 2012, partially offset by a $0.5 million after-tax gain on disposal of assets.

Fortis Properties delivered earnings of $22 million compared to $23 million for 2011. The Company acquired the 126-room StationPark All Suite Hotel in London, Ontario for approximately $13 million, inclusive of debt assumed, in October 2012.

Corporate and other expenses were $88 million compared to $61 million for 2011. Excluding CH Energy Group acquisition-related expenses, incurred largely in the first half of 2012, and the merger termination fee paid to Fortis in July 2011, corporate and other expenses were $8.5 million higher year over year. The increase was mainly the result of a $2 million foreign exchange loss recognized in 2012 compared to a $1.5 million after-tax net foreign exchange gain recognized in 2011, certain non-recurring operating expenses in 2012 and lower effective income tax recoveries, partially offset by lower finance charges.

Cash flow from operating activities was $976 million, up $61 million from 2011, driven by higher earnings and the collection of increased depreciation and amortization expense in customer rates.

Earnings for the fourth quarter were $87 million, or $0.46 per common share, up $5 million, or $0.02 per common share, from the same quarter in 2011. Improved performance at the Canadian Regulated Electric Utilities, led by FortisAlberta, was partially offset by lower non-regulated hydroelectric generation mainly in Belize, lower earnings contribution from the Canadian Regulated Gas Utilities and higher corporate expenses. The decrease in earnings at the Canadian Regulated Gas Utilities was driven by the timing of operating expenses during 2012 and lower capitalized AFUDC.

Fortis is one of the highest-rated utility holding companies in North America with its corporate debt rated A- by Standard & Poor's and A(low) by DBRS, unchanged from 2011. The credit ratings were affirmed in 2012, reflecting several factors, notably the diversity of the Corporation's utility asset mix, as well as its financing plans for the pending acquisition of CH Energy Group and the expected completion of the Waneta Expansion on time and on budget.

Fortis raised gross proceeds of approximately $601 million, upon issuance of 18.5 million Subscription Receipts at $32.50 each in June 2012, to finance a portion of the purchase price of CH Energy Group. The proceeds are being held by an escrow agent, pending satisfaction of closing conditions, including receipt of regulatory approvals, contained in the agreement to acquire CH Energy Group. Each Subscription Receipt will entitle the holder thereof to receive, on satisfaction of the closing conditions, one common share of Fortis. The Corporation issued $200 million 4.75% preference shares in November 2012, the net proceeds of which were used to repay borrowings under its committed corporate credit facility, which borrowings were primarily incurred to support the construction of the Waneta Expansion and for other general corporate purposes. FortisAlberta raised $125 million 40-year 3.98% unsecured debentures, largely in support of its capital expenditure program, in October 2012.

Fortis retroactively adopted accounting principles generally accepted in the United States ("US GAAP"), effective January 1, 2012, with the restatement of prior periods. The adoption of US GAAP did not have a material impact on the Corporation's earnings or earnings per common share for 2012 and 2011.

"We look forward to welcoming the employees of CH Energy Group to the Fortis Group. Their proven track record for providing customers with quality service will further enhance the positioning of Fortis as a leader in the North American utility industry," says Marshall.

Central Hudson was recently recognized by the Edison Electric Institute ("EEI"), an association of electric companies representing 70% of the U.S. electric power industry, for its restoration work in response to Superstorm Sandy. Several FortisOntario crews worked with Central Hudson employees to reconnect some 104,000 customers who had been impacted by the storm. Two previous EEI Emergency Recovery Awards recognized Central Hudson's recovery efforts following severe snowstorms in October 2011 and February 2010, the latter being the most severe storm in the utility's history.

"Execution of our $1.3 billion capital program for 2013 is progressing well," says Marshall. "Capital investment will support continuing growth in earnings and dividends and will be mostly funded with cash from operations and long-term debt at the regulated utility level," he adds.

Over the five years 2013 through 2017, the Corporation's capital program, including expenditures at Central Hudson, is expected to total approximately $6 billion. Capital investment over that period is expected to allow utility rate base and hydroelectric generation investment to increase at a combined compound annual growth rate of approximately 6%.

"Serving our customers well is our utmost priority. We are also focused on closing the CH Energy Group acquisition," concludes Marshall.

Financial Highlights

For the three and twelve months ended December 31, 2012

Dated February 7, 2013

FORWARD-LOOKING STATEMENT

The following Fortis Inc. ("Fortis" or the "Corporation") fourth quarter 2012 earnings release should be read in conjunction with the following: (i) the audited consolidated financial statements and notes thereto for the year ended December 31, 2011, prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") and voluntarily filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") by Fortis on March 16, 2012; and (ii) the "Supplemental Interim Consolidated Financial Statements for the Year Ended December 31, 2011 (Unaudited)" contained in the above-noted voluntary filing, which provides a detailed reconciliation between the Corporation's interim unaudited consolidated 2011 financial statements prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP") and interim unaudited consolidated 2011 financial statements prepared in accordance with US GAAP; (iii) the interim Management Discussion and Analysis ("MD&A") and unaudited consolidated financial statements and notes thereto for the three and nine months ended September 30, 2012, prepared in accordance with US GAAP; and (iv) the MD&A and audited consolidated financial statements and notes thereto for the year ended December 31, 2011, prepared in accordance with Canadian GAAP, included in the Corporation's 2011 Annual Report. Financial information for 2012 and comparative periods contained in this material have been prepared in accordance with US GAAP and are presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in this fourth quarter 2012 earnings release within the meaning of applicable securities laws in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation.The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs and is based on information currently available to management. The forward-looking information in this fourth quarter 2012 earnings release includes, but is not limited to, statements regarding: the Corporation's consolidated forecasted gross capital expenditures for 2013; total gross capital expenditures over the five-year period 2013 through 2017 and average annual capital expenditures at Central Hudson Gas & Electric Corporation over the same time period; the nature, timing and amount of certain capital projects and their expected costs and time to complete; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; the expected timing of filing regulatory applications and of receipt of regulatory decisions; the expected timing of the closing of the acquisition of CH Energy Group, Inc. ("CH Energy Group") by Fortis and the expectation that the acquisition will be accretive to earnings per common share of Fortis within the first full year of ownership, excluding acquisition-related expenses; an expected favourable impact on the Corporation's earnings in future periods upon final enactment of legislative changes to Part VI.1 taxes; the expectation that the acquisition of the City of Kelowna's electrical utility assets by FortisBC Electric will close by the end of the first quarter of 2013; the expected combined compound annual growth rate of utility rate base and hydroelectric generation investment over the next five years; and the Corporation's expected regulated midyear rate base in 2013 upon closing of the CH Energy Group acquisition.

The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate orders and no material adverse regulatory decisions being received; FortisAlberta continues to recover its cost of service and earn its allowed rate of return on common shareholder's equity ("ROE") under performance-based rate-setting ("PBR"), which commenced for a five-year term effective January 1, 2013; the acquisition of the City of Kelowna's electrical utility assets will be approved by the regulator; the receipt of regulatory approval from the New York State Public Service Commission of a settlement agreement, as filed, pertaining to the acquisition of CH Energy Group; the closing of the acquisition of CH Energy Group before the expiry of the Subscription Receipts on June 30, 2013; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the gas and electricity systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; no material capital project and financing cost overrun related to the construction of the Waneta Expansion hydroelectric generating facility; sufficient liquidity and capital resources; the expectation that the Corporation will receive appropriate compensation from the Government of Belize ("GOB") for fair value of the Corporation's investment in Belize Electricity that was expropriated by the GOB; the expectation that Belize Electric Company Limited will not be expropriated by the GOB; the expectation that the Corporation will receive fair compensation from the Government of Newfoundland and Labrador related to the expropriation of the Exploits River Hydro Partnership's hydroelectric assets and water rights; the continuation of regulator-approved mechanisms to flow through the commodity cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas commodity prices and fuel prices; no significant counterparty defaults;
the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; the absence of significant changes in government energy plans and environmental laws that may materially negatively affect the operations and cash flows of the Corporation and its subsidiaries; no material change in public policies and directions by governments that could materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the ability to report under US GAAP beyond 2014 or the adoption of International Financial Reporting Standards after 2014 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; and sufficient human resources to deliver service and execute the capital program.

The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Risk factors, which could cause results or events to differ from current expectations, are detailed under the heading "Business Risk Management" in the Corporation's MD&A for the three and nine months ended September 30, 2012, for the year ended December 31, 2011 and as otherwise disclosed in this fourth quarter 2012 earnings release. Key risk factors for 2013 include, but are not limited to: uncertainty of the impact a continuation of a low interest rate environment may have on the allowed ROE at each of the Corporation's four large Canadian regulated utilities; uncertainty regarding the treatment of certain capital expenditures at FortisAlberta under the newly implemented PBR mechanism; risks relating to the ability to close the acquisition of CH Energy Group, the timing of such closing and the realization of the anticipated benefits of the acquisition; and risk associated with the amount of compensation to be paid to Fortis for its investment in Belize Electricity that was expropriated by the GOB; and the timeliness of the receipt of the compensation and the ability of the GOB to pay the compensation owing to Fortis.

All forward-looking information in this fourth quarter 2012 earnings release is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.

CORPORATE OVERVIEW

Fortis is the largest investor-owned distribution utility in Canada, serving more than 2 million gas and electricity customers. Its regulated holdings include electric utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia, Canada. Fortis owns non-regulated generation assets, primarily hydroelectric, across Canada and in Belize and Upstate New York, and hotels and commercial office and retail space in Canada. In 2012 the Corporation's electricity distribution systems met a combined peak demand of 5,244 megawatts ("MW") and its gas distribution system met a peak day demand of 1,336 terajoules. For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three and nine months ended September 30, 2012 and to the "Corporate Overview" section of the 2011 Annual MD&A.

The key goals of the Corporation's regulated utilities are to operate sound gas and electricity distribution systems; deliver safe, reliable cost-efficient energy to customers; and conduct business in an environmentally responsible manner. The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are primarily determined under cost of service ("COS") regulation.

Generally under COS regulation, the respective regulatory authority sets customer gas and/or electricity rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholder's equity ("ROE") and/or rate of return on rate base assets ("ROA") depends on the utility achieving the forecasts established in the rate-setting processes. As such, earnings of regulated utilities are generally impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; and (vi) timing differences within an annual financial reporting period, between when actual expenses are incurred and when they are recovered from customers in rates. When forward test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.

When performance-based rate-setting ("PBR") mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow the utility a reasonable opportunity to recover prudent COS and earn its allowed ROE.

UPDATE ON SIGNIFICANT ITEMS

Pending Acquisition of CH Energy Group, Inc.: In February 2012 Fortis announced that it had entered into an agreement to acquire CH Energy Group, Inc. ("CH Energy Group") for US$65.00 per common share in cash, for an aggregate purchase price of approximately US$1.5 billion, including the assumption of approximately US$500 million of debt on closing. CH Energy Group is an energy delivery company headquartered in Poughkeepsie, New York. Its main business, Central Hudson Gas & Electric Corporation ("Central Hudson"), is a regulated transmission and distribution ("T&D") utility serving approximately 300,000 electric and 75,000 natural gas customers in eight counties of New York State's Mid-Hudson River Valley. The transaction received CH Energy Group shareholder approval in June 2012 and regulatory approval from the Federal Energy Regulatory Commission and the Committee on Foreign Investment in the United States in July 2012. In addition, the waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired in October 2012, satisfying another condition necessary for consummation of the transaction.

Approval by the New York State Public Service Commission ("NYSPSC") of the Corporation's acquisition of CH Energy Group is the last significant regulatory matter required to close the transaction. Closing of the transaction is now anticipated during the second quarter of 2013. The transaction is expected to be accretive to the Corporation's earnings per common share within the first full year of ownership of CH Energy Group, excluding acquisition-related expenses. A Settlement Agreement, among Fortis, CH Energy Group, NYSPSC staff, registered interveners, and other parties was filed with the NYSPSC in January 2013. The Settlement Agreement provides almost $50 million to fund customer and community benefits, including: (i) $35 million to cover expenses that normally would be recovered in customer rates, for example, storm-restoration expenses; (ii) guaranteed savings to customers of more than $9 million over five years resulting from the elimination of costs Central Hudson now incurs as a public company; and (iii) the establishment of a $5 million Customer Benefit Fund for economic development and low-income assistance programs for communities and residents of the Mid-Hudson River Valley. Another benefit provided under the Settlement Agreement is an electric and natural gas customer delivery rate freeze until July 1, 2014. The Settlement Agreement also contains customer protections, including the continuation of Central Hudson as a stand-alone utility. The parties to the Settlement Agreement have concluded that, based on the terms of the Settlement Agreement, the acquisition is in the public interest and have recommended approval by the NYSPSC.

During 2012 the Corporation's earnings were reduced by the incurrence of $7.5 million of after-tax CH Energy Group acquisition-related expenses, largely incurred in the first half of 2012.

Subscription Receipts Offering: To finance a portion of the pending acquisition of CH Energy Group, Fortis sold 18.5 million Subscription Receipts at $32.50 each in June 2012 through a bought deal offering underwritten by a syndicate of underwriters, realizing gross proceeds of approximately $601 million. The gross proceeds from the sale of the Subscription Receipts are being held by an escrow agent, pending satisfaction of closing conditions, including receipt of regulatory approvals, included in the agreement to acquire CH Energy Group (the "Release Conditions"). The Subscription Receipts began trading on the Toronto Stock Exchange on June 27, 2012 under the symbol "FTS.R".

Each Subscription Receipt will entitle the holder thereof to receive, on satisfaction of the Release Conditions and without payment of additional consideration, one common share of Fortis and a cash payment equal to the dividends declared on Fortis common shares during the period from June 27, 2012 to the date of issuance of the common shares in respect of the Subscription Receipts to holders of record.

If the Release Conditions are not satisfied by June 30, 2013, or if the agreement and plan of merger relating to the acquisition of CH Energy Group is terminated prior to such time, holders of Subscription Receipts shall be entitled to receive from the escrow agent an amount equal to the full subscription price thereof plus their pro rata share of the interest earned on such amount. Closing of the acquisition of CH Energy Group subsequent to June 30, 2013 could result in the Corporation having to raise alternative capital to finance the transaction.

Receipt of Regulatory Decisions: Regulatory decisions were received in 2012 for 2012/2013 revenue requirements at the FortisBC Energy companies and FortisBC Electric, and for 2012 revenue requirements at FortisAlberta. The Alberta Utilities Commission ("AUC") issued a generic decision in September 2012 on its PBR Initiative, outlining the PBR framework applicable to distribution utilities in Alberta for a five-year term, which commenced January 1, 2013. For further information, refer to the "Regulatory Highlights" section of this earnings release.

First Preference Share Offering: In November 2012 Fortis issued 8 million 4.75% First Preference Shares, Series J at $25.00 per share for total proceeds of $200 million. The net proceeds of $194 million were used to repay borrowings under the Corporation's committed corporate credit facility, which borrowings were primarily incurred to support the construction of the non-regulated Waneta Expansion hydroelectric generating facility ("Waneta Expansion") and for other general corporate purposes.

Long-Term Debt Offering - FortisAlberta: In October 2012 FortisAlberta issued 40-year $125 million 3.98% unsecured debentures. The net proceeds of the debt offering are being used to repay borrowings under the Company's credit facility incurred to finance capital expenditures, to fund future capital expenditures, and for general corporate purposes.

Part VI.1 Tax: Under the terms of the Corporation's first preference shares, the Corporation is subject to tax under Part VI.1 of the Income Tax Act (Canada) associated with dividends on its first preference shares. For corporations subject to Part VI.1 tax, there is an equivalent Part I tax deduction. As permitted under the Income Tax Act (Canada), a corporation may allocate its Part VI.1 tax liability and equivalent Part I tax deduction to its related subsidiaries. In the past, Fortis has allocated these items to Maritime Electric, Newfoundland Power and FortisOntario.

Upon transition to US GAAP, the Corporation reduced its consolidated opening 2012 retained earnings by $20 million to reflect the impact of differences between enacted and substantively enacted tax legislation associated with prior assessments and payments of Part VI.1 taxes, and the recovery of Part I taxes. The adjustment was done as US GAAP requires tax provisions to be based on enacted legislation versus substantively enacted legislation. A number of legislative amendments to Part VI.1 tax in Canada have yet to be enacted. The above-noted transitional US GAAP adjustment, as well as certain amounts recognized in 2012, will reverse through the Corporation's earnings in future periods when the legislation is finally enacted, which is expected in 2013, or as reassessment of corporate taxation years, upon which the enacted versus the substantively enacted rates were used to calculate taxes payable under US GAAP, become statute barred. During 2012 Newfoundland Power recorded a favourable $2.5 million adjustment to income taxes associated with statute-barred Part VI.1 taxes (2011 - $1 million).

Hotel Acquisition: In October 2012 Fortis Properties acquired the 126-room StationPark All Suite Hotel ("StationPark Hotel") in London, Ontario for approximately $13 million, inclusive of debt assumed of approximately $6 million.

Pending Acquisitionof the Electrical Utility Assets from the City of Kelowna: FortisBC Electric has offered to purchase the City of Kelowna's electrical utility assets, which currently serve some 15,000 customers, for approximately $55 million. FortisBC Electric provides the City of Kelowna with electricity under a wholesale tariff and has operated and maintained the City of Kelowna's electrical utility assets under contract since 2000. Closing of the transaction, which is subject to satisfaction of certain conditions and receipt of applicable approvals, including regulatory approval, is expected by the end of the first quarter of 2013. An application was filed with the regulator in November 2012 requesting approval of the transaction.

Transition to US GAAP: Effective January 1, 2012, Fortis retroactively adopted US GAAP with the restatement of comparative reporting periods.

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of profitable growth with earnings per common share as the primary measure of performance. The Corporation's business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the fourth quarters and years ended December 31, 2012 and December 31, 2011 are provided in the following table.

Consolidated Financial Highlights (Unaudited)

Periods Ended December 31

Quarter

Annual

($ millions, except for common share data)

2012

2011

Variance

2012

2011

Variance

Revenue

999

1,034

(35

)

3,654

3,738

(84

)

Energy Supply Costs

430

490

(60

)

1,522

1,697

(175

)

Operating Expenses

247

233

14

868

850

18

Depreciation and Amortization

119

107

12

470

416

54

Other Income, Net

6

6

-

4

38

(34

)

Finance Charges

90

88

2

366

363

3

Income Taxes

17

26

(9

)

61

84

(23

)

Net Earnings

102

96

6

371

366

5

Net Earnings Attributable to:

Non-Controlling Interests

2

2

-

9

9

-

Preference Equity Shareholders

13

12

1

47

46

1

Common Equity Shareholders

87

82

5

315

311

4

Net Earnings

102

96

6

371

366

5

Basic Earnings per Common Share ($)

0.46

0.44

0.02

1.66

1.71

(0.05

)

Diluted Earnings per Common Share ($)

0.45

0.43

0.02

1.65

1.70

(0.05

)

Weighted Average Number of Common Shares Outstanding (# millions)

191.0

188.1

2.9

190.0

181.6

8.4

Cash Flow from Operating Activities

172

230

(58

)

976

915

61

Factors Contributing to Quarterly and Annual

Revenue Variances

Unfavourable

Lower commodity cost of natural gas charged to customers

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011, which reduced revenue year over year

Decreased non-regulated hydroelectric production, mainly due to lower rainfall and a generating facility in Upstate New York being out of service in 2012

Decreased electricity sales at FortisBC Electric for the quarter

Favourable

An increase in gas delivery rates and the base component of electricity rates at most of the regulated utilities, consistent with rate decisions, reflecting ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers

Net transmission revenue of approximately $2 million recognized for the quarter and $8.5 million recognized for the year at FortisAlberta, as a result of the 2012 distribution revenue requirements decision received in April 2012

The flow through in customer electricity rates of higher energy supply costs, where applicable, at most of the regulated electric utilities, which increased revenue

Increased electricity sales at Newfoundland Power and Maritime Electric

A $4 million increase in franchise fee revenue at FortisAlberta for the year

Growth in the number of customers, driven by FortisAlberta

Higher pole-attachment revenue at FortisBC Electric, and differences in the amount of PBR incentives refunded to FortisBC Electric's customers period over period

Higher Hospitality revenue at Fortis Properties for the year, driven by revenue from the Hilton Suites Winnipeg Airport hotel ("Hilton Suites Hotel"), which was acquired in October 2011, and higher Hospitality revenue for the quarter, due to revenue from the StationPark Hotel, which was acquired in October 2012

Factors Contributing to Quarterly and Annual

Energy Supply Costs Variances

Favourable

Lower commodity cost of natural gas

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011, which reduced energy supply costs year over year

Decreased electricity sales at FortisBC Electric for the quarter, which reduced power purchases

Unfavourable

Increased fuel prices at Caribbean Utilities and increased purchased power costs at FortisBC Electric, Newfoundland Power and FortisOntario

An increase in the base amount of energy supply costs expensed at Maritime Electric in accordance with the operation of the Energy Cost Adjustment Mechanism

Increased electricity sales at Newfoundland Power and Maritime Electric, which increased power purchases

Factors Contributing to Quarterly and Annual

Operating Expenses Variances

Unfavourable

General inflationary and employee-related cost increases at the Corporation's regulated utilities, and increased franchise fee expenses at FortisAlberta for the year

Increased operating expenses at the FortisBC Energy companies for the quarter, mainly due to the timing of certain expenses during 2012, including consulting and contracting expenses

Higher operating expenses at Fortis Properties for the year, mainly associated with the Hilton Suites Hotel, which was acquired in October 2011, and higher operating expenses for the quarter associated with the StationPark Hotel, which was acquired in October 2012

A $3 million non-recurring provision recognized in the fourth quarter of 2012 associated with the Corporation's investment in CustomerWorks Limited Partnership ("CWLP")

Favourable

Reduced operating expenses at the FortisBC Energy companies during 2012, mainly due to the accrual of non-asset retirement obligation ("non-ARO") removal costs in depreciation, effective January 1, 2012, and lower customer care-related costs as a result of insourcing the customer care function, effective January 1, 2012. Non-ARO removal costs were recorded in operating expenses in 2011.

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011, which decreased operating expenses year over year

Lower operating expenses at FortisBC Electric for the quarter, due to the timing of certain expenses during 2012

Factors Contributing to Quarterly and Annual

Depreciation and Amortization Expense Variances

Unfavourable

Continued investment in energy infrastructure

Increased depreciation at the FortisBC Energy companies, mainly due to the accrual of non-ARO removal costs in depreciation, effective January 1, 2012, as discussed above

Favourable

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011, which decreased depreciation year over year

Lower depreciation rates at FortisAlberta and FortisBC Electric, effective January 1, 2012, as a result of the 2012 revenue requirements decisions received in April 2012 and August 2012, respectively

Factors Contributing to Quarterly and Annual

Other Income, Net Variances

Unfavourable

The $17 million (US$17.5 million) ($11 million after-tax) fee paid to Fortis in July 2011 following the termination of a Merger Agreement between Fortis and Central Vermont Public Service Corporation ("CVPS"), which increased other income in 2011

Approximately $9 million ($7.5 million after tax) of costs, incurred largely in the first half of 2012, related to the pending acquisition of CH Energy Group

A foreign exchange loss of approximately $2 million recognized for the year associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity. A net foreign exchange gain of approximately $1 million ($1.5 million after tax) was recognized in 2011 related to the above item.

Lower capitalized equity component of allowance for funds used during construction ("AFUDC") for the year, mainly at the FortisBC Energy companies

An approximate $1 million gain on the sale of property at FortisAlberta during the first quarter of 2011

Favourable

A foreign exchange gain of approximately $1 million recognized in the fourth quarter of 2012, compared to a net foreign exchange loss of $0.5 million ($1 million after tax) recognized in the fourth quarter of 2011, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity

An approximate $1 million ($0.5 million after-tax) gain recognized in the fourth quarter of 2012 on the involuntary disposition of assets, associated with damaged equipment at a generating facility in Upstate New York and related proceeds received under an insurance claim

Factors Contributing to Quarterly and Annual

Finance Charges Variances

Unfavourable

Higher long-term debt levels in support of the utilities' capital expenditure programs

Lower capitalized debt component of AFUDC at the regulated utilities, mainly at the FortisBC Energy companies

Favourable

Higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011, which decreased finance charges year over year

Lower short-term borrowings at the regulated utilities year over year

Factors Contributing to Quarterly and Annual

Income Taxes Variances

Favourable

Lower statutory income tax rates and lower earnings before income taxes

Differences in deductions for income tax purposes compared to accounting purposes period over period

Factors Contributing to Quarterly Earnings Variance

Favourable

Increased earnings at FortisAlberta, mainly due to rate base growth, net transmission revenue of $2 million recognized in the fourth quarter of 2012, and the rate revenue reduction accrual during the fourth quarter of 2011, reflecting the cumulative impact from January 1, 2011 of the decrease in the allowed ROE for 2011

Increased earnings at Other Canadian Regulated Electric Utilities, mainly due to lower effective income taxes at Maritime Electric and the accrual of cumulative return earned on FortisOntario's capital investment in smart meters

Increased earnings at FortisBC Electric, due to rate base growth, lower-than-expected finance charges in 2012, higher pole-attachment revenue and the expiry of the PBR mechanism on December 31, 2011

Unfavourable

Decreased non-regulated hydroelectric production, mainly in Belize due to lower rainfall, partially offset by an approximate $0.5 million after-tax gain recognized in the fourth quarter of 2012 on the involuntary disposition of generation assets in Upstate New York

Increased corporate expenses, largely due to the $3 million non-recurring provision recognized in the fourth quarter of 2012 and lower effective income tax recoveries, partially offset by a foreign exchange gain of approximately $1 million recognized in the fourth quarter of 2012, compared to an after-tax net foreign exchange loss of approximately $1 million recognized in the fourth quarter of 2011, and lower finance charges

Decreased earnings at the FortisBC Energy companies, due to the timing of certain operating and maintenance expenses during 2012, lower capitalized AFUDC and lower-than-expected customer additions in 2012, partially offset by rate base growth, higher gas transportation volumes to industrial customers and lower effective income taxes

Factors Contributing to Annual Earnings Variance

Favourable

Increased earnings at FortisAlberta, due to rate base growth, net transmission revenue of $8.5 million recognized in 2012, and lower-than-expected depreciation expense and finance charges in 2012, partially offset by an approximate $1 million gain on the sale of property during the first quarter of 2011

Increased earnings at Newfoundland Power, mainly due to lower effective income taxes, a higher allowed ROE and electricity sales growth, partially offset by the impact of the support structure arrangements with Bell Aliant Regional Communications Inc. ("Bell Aliant") during 2011, higher purchased power costs and higher depreciation expense

Increased earnings at Other Canadian Regulated Electric Utilities, largely for the same reasons discussed above for the quarter

Increased earnings at FortisBC Electric, due to rate base growth, higher pole-attachment revenue and lower-than-expected finance charges in 2012, partially offset by the expiry of the PBR mechanism on December 31, 2011

Higher corporate expenses due to: (i) the favourable impact in 2011 of the $11 million after-tax fee paid to Fortis in July 2011 following the termination of a Merger Agreement between Fortis and CVPS; (ii) approximately $7.5 million of after-tax costs incurred in 2012 related to the pending acquisition of CH Energy Group; (iii) a $2 million foreign exchange loss recognized in 2012 compared to a $1.5 million after-tax net foreign exchange gain recognized in 2011; (iv) the $3 million non-recurring provision recognized in the fourth quarter of 2012; and (v) lower effective income tax recoveries. The above items were partially offset by lower finance charges, primarily due to higher capitalized interest associated with financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion.

Decreased non-regulated hydroelectric production, mainly due to lower rainfall and a generating facility in Upstate New York being out of service in 2012, partially offset by an approximate $0.5 million after-tax gain recognized in the fourth quarter of 2012 on the involuntary disposition of generation assets in Upstate New York

For an update on material regulatory decisions and applications pertaining to the Corporation's regulated utilities, refer to the "Regulatory Highlights" section of this earnings release. A discussion of the financial results of the Corporation's reporting segments is as follows.

Higher gas transportation volumes to industrial customers, due to certain customers switching to natural gas from alternative sources of fuel as a result of low natural gas prices

With the implementation of the Customer Care Enhancement Project on January 1, 2012, the FortisBC Energy companies changed their definition of a customer. As a result of this change, the FortisBC Energy companies reduced their combined customer count by approximately 18,000, as at January 1, 2012. As at December 31, 2012, the total number of customers served by the FortisBC Energy companies was approximately 945,000.

The FortisBC Energy companies earn approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulator-approved deferral mechanisms, changes in consumption levels and the commodity cost of natural gas from those forecast to set residential and commercial customer gas rates do not materially affect earnings.

Seasonality has a material impact on the earnings of the FortisBC Energy companies as a major portion of the gas distributed is used for space heating. Most of the annual earnings of the FortisBC Energy companies are realized in the first and fourth quarters.

Factors Contributing to Quarterly and Annual

Revenue Variances

Unfavourable

Lower commodity cost of natural gas charged to customers

Lower average gas consumption by residential and commercial customers

Lower-than-expected customer additions in 2012

Favourable

A net increase in the delivery component of customer rates, effective January 1, 2012, mainly due to ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers as reflected in the 2012/2013 revenue requirements decision received in April 2012

Higher gas transportation volumes to industrial customers

Factors Contributing to Quarterly Earnings Variance

Unfavourable

The timing of certain operating and maintenance expenses during 2012

Lower capitalized AFUDC, due to lower assets under construction period over period

Lower-than-expected customer additions in 2012

Favourable

Rate base growth, due to continued investment in energy infrastructure

Higher gas transportation volumes to industrial customers

Lower effective income taxes

Factors Contributing to Annual Earnings Variance

Favourable

Rate base growth, due to continued investment in energy infrastructure

Higher gas transportation volumes to industrial customers

Lower-than-expected operating and maintenance expenses during 2012

Lower effective income taxes

Unfavourable

Lower-than-expected customer additions in 2012

Lower capitalized AFUDC, for the same reason discussed above for the quarter

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Energy Deliveries (gigawatt hours ("GWh"))

4,365

4,232

133

16,799

16,367

432

Revenue ($ millions)

113

102

11

448

408

40

Earnings ($ millions)

23

16

7

96

74

22

Factors Contributing to Quarterly and Annual

Energy Deliveries Variances

Favourable

Higher average consumption by oilfield and commercial customers, due to increased activity

Higher average consumption by residential customers, driven by cooler temperatures in the fourth quarter, which increased heating load

Growth in the number of customers, mainly in the residential and commercial sectors, with the total number of customers increasing by approximately 9,000 year over year, driven by favourable economic conditions

As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Net transmission revenue of approximately $2 million recognized in the fourth quarter of 2012. In its April 2012 distribution revenue requirements decision, the regulator did not approve the continuation in 2012 of the deferral of transmission volume variances associated with FortisAlberta's Alberta Electric System Operator ("AESO") charges deferral account. In the absence of full deferral, FortisAlberta was subject to volume risk in 2012 on actual transmission costs relative to those charged to customers based on forecast volumes and prices. Transmission volumes are influenced by many factors, which may result in actual transmission volumes varying from those forecasted. The deferral of transmission volume variances was reinstated, effective January 1, 2013, as approved by the regulator and, therefore, such variances will not impact earnings in 2013.

Growth in the number of customers

The cumulative impact on revenue, from January 1, 2011, of the decrease in the allowed ROE to 8.75%, effective for both 2011 and 2012, from 9.00% for 2010 was recognized during the fourth quarter of 2011, when the regulatory decision was received. As a result, an approximate $2 million rate revenue reduction was accrued during the fourth quarter of 2011, of which approximately $1.5 million related to the first three quarters of 2011.

An increase in franchise fee revenue of approximately $1 million

Factors Contributing to Annual Revenue Variance

Favourable

An increase in customer electricity distribution rates, for the same reason discussed above for the quarter

Net transmission revenue of approximately $8.5 million recognized in 2012, for the same reason discussed above for the quarter

Growth in the number of customers

An increase in franchise fee revenue of approximately $4 million

Factors Contributing to Quarterly Earnings Variance

Favourable

Rate base growth, due to continued investment in energy infrastructure, which is being favourably impacted by growth in the number of customers

Net transmission revenue of approximately $2 million recognized in the fourth quarter of 2012, as a result of the distribution revenue requirements decision received in April 2012

The rate revenue reduction accrual during the fourth quarter of 2011, reflecting the cumulative impact from January 1, 2011 of the decrease in the allowed ROE for 2011

Factors Contributing to Annual Earnings Variance

Favourable

Rate base growth, for the same reason discussed above for the quarter

Net transmission revenue of approximately $8.5 million recognized in 2012, for the same reason discussed above for the quarter

Lower-than-expected depreciation expense in 2012, mainly due to construction projects being completed later in the year and lower AESO transmission-related capital expenditures

Lower-than-expected finance charges in 2012 associated with the timing of debt issuances and associated interest rates on the debt

Unfavourable

An approximate $1 million gain on the sale of property during the first quarter of 2011

FORTISBC ELECTRIC(1)

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Electricity Sales (GWh)

830

843

(13

)

3,143

3,143

-

Revenue ($ millions)

81

81

-

306

296

10

Earnings ($ millions)

12

10

2

50

48

2

(1)

Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants and the electrical utility assets owned by the City of Kelowna. Excludes the non-regulated generation operations of FortisBC Inc.'s wholly owned partnership, Walden Power Partnership.

Factor Contributing to Quarterly Electricity Sales Variance

Unfavourable

Lower average consumption, due to warmer weather

Factors Contributing to Quarterly and Annual

Revenue Variances

Favourable

An overall increase in customer electricity rates, effective January 1, 2012, mainly due to ongoing investment in energy infrastructure and forecasted certain higher expenses recoverable from customers as reflected in the 2012/2013 revenue requirements decision received in August 2012

A 1.4% increase in customer electricity rates, effective June 1, 2011, as a result of the flow through to customers of increased purchased power costs charged to FortisBC Electric by BC Hydro, which increased revenue for the year

Higher pole-attachment revenue

Higher wheeling revenue for the year

Differences in the amount of PBR incentives refunded to customers period over period

Unfavourable

Decreased electricity sales for the quarter

Factors Contributing to Quarterly Earnings Variance

Favourable

Rate base growth, due to continued investment in energy infrastructure

Lower-than-expected finance charges in 2012. As approved in the 2012/2013 revenue requirements decision received in August 2012, variances between actual finance charges and those forecasted in determining customer electricity rates, beginning January 1, 2012, are no longer permitted deferral account treatment and, therefore, favourably impacted earnings in 2012.

Higher pole-attachment revenue

The expiry of the PBR mechanism on December 31, 2011. In the fourth quarter of 2011, lower-than-expected electricity revenue and higher-than-expected operating expenses, which were shared equally between customers and FortisBC Electric under the PBR mechanism, unfavourably impacted earnings in that quarter. Pursuant to the Company's 2012/2013 revenue requirements decision received in August 2012, variances between actual electricity revenue and purchased power costs and those used in determining customer electricity rates were subject to full deferral account treatment and, therefore, did not impact earnings in the fourth quarter of 2012.

Factors Contributing to Annual Earnings Variance

Favourable

Rate base growth, for the same reason discussed above for the quarter

Higher pole-attachment revenue

Lower-than-expected finance charges, for the same reason discussed above for the quarter

Unfavourable

The expiry of the PBR mechanism on December 31, 2011. In 2011 lower-than-expected costs, primarily purchased power costs, which were shared equally between customers and FortisBC Electric under the PBR mechanism, favourably impacted earnings in that year. In 2012 variances between actual electricity revenue and purchased power costs and those used in determining customer electricity rates were subject to full deferral account treatment and, therefore, did not impact earnings in 2012.

NEWFOUNDLAND POWER

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Electricity Sales (GWh)

1,539

1,527

12

5,652

5,553

99

Revenue ($ millions)

159

156

3

581

573

8

Earnings ($ millions)

9

8

1

37

32

5

Factors Contributing to Quarterly and Annual

Electricity Sales Variances

Favourable

Growth in the number of customers

Higher concentration of electric-versus-oil heating in new home construction combined with economic growth, which increased consumption

Unfavourable

Sunnier weather conditions, which reduced average consumption

Factor Contributing to Quarterly Revenue Variance

Favourable

The 0.8% increase in electricity sales

Factors Contributing to Annual Revenue Variance

Favourable

The 1.8% increase in electricity sales

Increased amortization to revenue of regulatory liabilities and deferrals, as approved by the regulator

Unfavourable

Revenue for 2011 included amounts related to support structure arrangements, which were in place with Bell Aliant during 2011, associated with the joint-use poles and related infrastructure held for sale to Bell Aliant. The joint-use poles and related infrastructure were sold in October 2011.

Factors Contributing to Quarterly Earnings Variance

Favourable

An increase in the allowed ROE from 8.38% to 8.80%, effective January 1, 2012, which was accrued in 2012, as approved by the regulator, as a decrease in operating expenses for deferred recovery from customers

Higher purchased power costs, as a result of lower generation associated with the Company's hydroelectric generating facilities in 2012 due to lower water inflows

Higher depreciation, due to continued investment in energy infrastructure

Factors Contributing to Annual Earnings Variance

Favourable

Lower effective income taxes, primarily due to lower Part VI.1 taxes, including the favourable impact of reversals of statute-barred Part VI.1 taxes, and a lower statutory income tax rate. For further information on Part VI.1 tax, refer to the "Update on Significant Items" section of this earnings release.

A higher allowed ROE, as discussed above for the quarter

Electricity sales growth

Unfavourable

The impact of the support structure arrangements with Bell Aliant during 2011, as discussed above

The same factors discussed above for the quarter

OTHER CANADIAN ELECTRIC UTILITIES(1)

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Electricity Sales (GWh)

578

568

10

2,381

2,366

15

Revenue ($ millions)

89

83

6

353

339

14

Earnings ($ millions)

6

2

4

24

20

4

(1)

Includes Maritime Electric and FortisOntario. FortisOntario mainly includes Canadian Niagara Power, Cornwall Electric and Algoma Power.

Factors Contributing to Quarterly Electricity Sales Variance

Favourable

Growth in the number of residential and commercial customers on Prince Edward Island ("PEI")

Higher average consumption by residential customers on PEI, due to colder temperatures, and an increase in the number of such customers using electricity for home heating

Higher average consumption by commercial customers in the agricultural processing sector on PEI

Factors Contributing to Annual Electricity Sales Variance

Favourable

The same factors discussed above for the quarter

Unfavourable

Lower average consumption by residential and industrial customers in Ontario, primarily during the first quarter of 2012, reflecting more moderate temperatures and weak economic conditions in the region

Factors Contributing to Quarterly and Annual

Revenue Variances

Favourable

The overall 1.8% and 0.6% increase in electricity sales for the quarter and year, respectively, for the reasons discussed above

An increase in the basic component of customer rates at Maritime Electric, effective March 1, 2012, associated with the higher flow through and recovery of energy supply costs

The accrual of cumulative return earned on FortisOntario's capital investment in smart meters, of which approximately $0.5 million related to prior years

The flow through in customer electricity rates of higher energy supply costs at FortisOntario

Increased base customer electricity rates at FortisOntario

Factors Contributing to Quarterly Earnings Variance

Favourable

Lower effective income taxes at Maritime Electric, primarily due to lower Part VI.1 taxes

The accrual of cumulative return earned on FortisOntario's capital investment in smart meters, of which approximately $0.5 million related to prior years

Increased operating expenses at Maritime Electric in the fourth quarter of 2011 associated with retirement costs

Lower operating expenses at FortisOntario in the fourth quarter of 2012, largely due to the timing of certain expenses during 2012

Factors Contributing to Annual Earnings Variance

Favourable

Lower effective income taxes at Maritime Electric, primarily due to lower Part VI.1 taxes

The accrual of cumulative return earned on FortisOntario's capital investment in smart meters, as discussed above for the quarter

Higher earnings contribution by FortisOntario's operations in Cornwall, due to an increase in base customer electricity rates

Net cost savings at FortisOntario in 2012 associated with the exercising of the Company's option to purchase all of the electricity distribution assets previously leased under an operating lease agreement with the City of Port Colborne

REGULATED ELECTRIC UTILITIES - CARIBBEAN(1)

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Average US:CDN Exchange Rate (2)

0.99

1.02

(0.03

)

1.00

0.99

0.01

Electricity Sales (GWh)

181

174

7

728

918

(190

)

Revenue ($ millions)

71

71

-

273

305

(32

)

Earnings ($ millions)

3

4

(1

)

19

20

(1

)

(1)

Includes Caribbean Utilities on Grand Cayman, Cayman Islands, in which Fortis holds an approximate 60% controlling ownership interest; three wholly owned utilities in the Turks and Caicos Islands, comprised of FortisTCI Limited, Atlantic Equipment & Power (Turks and Caicos) Ltd. and Turks and Caicos Utilities Limited, acquired in August 2012, (collectively "Fortis Turks and Caicos"); and the financial results of the Corporation's approximate 70% controlling ownership interest in Belize Electricity up to June 20, 2011. On June 20, 2011, the Government of Belize expropriated the Corporation's investment in Belize Electricity. As a result of no longer controlling the operations of the utility, Fortis discontinued the consolidation method of accounting for Belize Electricity, effective June 20, 2011. For further information, refer to the "Business Risk Management" section of the MD&A for three and nine months ended September 30, 2012.

(2)

The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity was the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.

Factors Contributing to Quarterly Electricity Sales Variance

Favourable

Electricity sales of 6 GWh for the quarter and 8 GWh year to date at Turks and Caicos Utilities Limited ("TCU"), which was acquired in August 2012

Higher tourism activity in the Turks and Caicos Islands

Growth in the number of customers, excluding the impact of customers acquired with TCU

Factors Contributing to Annual Electricity Sales Variance

Unfavourable

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011. Excluding Belize Electricity, electricity sales increased 0.6% year over year.

Higher rainfall and cooler temperatures experienced on Grand Cayman, which decreased air conditioning load, combined with continued weak economic conditions in the region

Favourable

The same factors discussed above for the quarter

Factors Contributing to Quarterly Revenue Variance

Unfavourable

Approximately $2 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue, due to the weakening of the US dollar relative to the Canadian dollar quarter over quarter

The discontinuance of government subsidization of FortisTCI Limited's ("FortisTCI's") South Caicos operations, effective April 1, 2012, in accordance with a rate decision received in February 2012

Favourable

Increased electricity sales at FortisTCI

The flow through in customer electricity rates of higher energy supply costs at Caribbean Utilities, due to an increase in the cost of fuel period over period, which increased revenue period over period

An increase in electricity rates for FortisTCI's large hotel customers, effective April 1, 2012, in accordance with a rate decision received in February 2012

An increase in base electricity rates at Caribbean Utilities, effective June 1, 2012

Factors Contributing to Annual Revenue Variance

Unfavourable

The expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011, which decreased revenue by approximately $45 million year over year

The discontinuance of government subsidization of FortisTCI's South Caicos operations, effective April 1, 2012, in accordance with a rate decision received in February 2012

Decreased electricity sales at Caribbean Utilities

Favourable

The same factors discussed above for the quarter

Approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, due to the strengthening of the US dollar relative to the Canadian dollar year over year

Excluding foreign exchange impacts, lower energy supply costs at FortisTCI, mainly due to more fuel-efficient production realized with the use of new generation units at the utility

FortisTCI acquired TCU in August 2012 for an aggregate purchase price of approximately $13 million (US$13 million), inclusive of debt assumed of $5 million (US$5 million). The utility serves more than 2,000 customers on Grand Turk and Salt Cay with a diesel-fired generating capacity of 9 MW.

NON-REGULATED - FORTIS GENERATION(1)

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Energy Sales (GWh)

50

112

(62

)

306

389

(83

)

Revenue ($ millions)

5

9

(4

)

31

34

(3

)

Earnings ($ millions)

2

5

(3

)

17

18

(1

)

(1)

Includes the financial results of non-regulated generation assets in Belize, Ontario, central Newfoundland, British Columbia and Upstate New York, with a combined generating capacity of 139 MW, mainly hydroelectric

Factor Contributing to Quarterly Energy Sales Variance

Unfavourable

Decreased production in Belize and Upstate New York, due to lower rainfall

Factors Contributing to Annual Energy Sales Variance

Unfavourable

Decreased production in Upstate New York, due to a generating facility being out of service and lower rainfall

Decreased production in Belize and Ontario, due to lower rainfall

Factors Contributing to Quarterly and Annual

Revenue Variances

Unfavourable

Decreased production in Belize and Upstate New York

Decreased production in Ontario for the year

Factors Contributing to Quarterly Earnings Variances

Unfavourable

Decreased production in Belize and Upstate New York

Favourable

An approximate $1 million ($0.5 million after-tax) gain recognized in the fourth quarter of 2012 on the involuntary disposition of assets, associated with damaged equipment at Moose River's hydroelectric generating facility in Upstate New York and related proceeds received under an insurance claim

Factors Contributing to Annual Earnings Variance

Unfavourable

Decreased production in Upstate New York and Ontario

Decreased production in Belize, partially offset by lower finance charges in Belize

Favourable

The approximate $1 million (0.5 million after-tax) gain on involuntary disposition of generation assets, for the same reason discussed above for the quarter

NON-REGULATED - FORTIS PROPERTIES (1)

Financial Highlights (Unaudited)

Quarter

Annual

Periods Ended December 31

2012

2011

Variance

2012

2011

Variance

Hospitality - Revenue per Available Room ("RevPar")

$ 73.94

$ 73.66

0.4

%

$ 80.00

$ 78.76

1.6

%

Real Estate - Occupancy Rate (as at) (2)

91.9

%

93.2

%

(1.4

)%

91.9

%

93.2

%

(1.4

)%

Hospitality Revenue ($ millions)

44

41

3

175

164

11

Real Estate Revenue ($ millions)

17

17

-

67

67

-

Total Revenue ($ millions)

61

58

3

242

231

11

Earnings ($ millions)

5

5

-

22

23

(1

)

(1)

Fortis Properties owns and operates 23 hotels, collectively representing more than 4,400 rooms in eight Canadian provinces, and approximately 2.7 million square feet of commercial office and retail space primarily in Atlantic Canada.

(2)

Reduced occupancy rate is primarily due to increased vacancy in New Brunswick.

Factors Contributing to Quarterly RevPar Variance

Favourable

A 0.6% increase in the average daily room rate, due to increases in western Canada and central Canada, partially offset by a decrease in Atlantic Canada

Unfavourable

A 0.2% decrease in occupancy, due to a decrease in central Canada, partially offset by increases in Atlantic Canada and western Canada

Factors Contributing to Annual RevPar Variance

Favourable

The Hilton Suites Hotel, acquired in October 2011, contributed 1.2% to the increase in RevPAR.

A 1.5% increase in the average daily room rate, excluding the impact of the Hilton Suites Hotel, due to increases in western Canada and central Canada

Unfavourable

A 1.1% decrease in occupancy, excluding the impact of the Hilton Suites Hotel, due to decreases in central Canada and Atlantic Canada, partially offset by an increase in western Canada

Factors Contributing to Quarterly Hospitality Revenue Variance

Favourable

Revenue contribution from the StationPark Hotel, which was acquired in October 2012

Higher revenue from operations in western Canada and Atlantic Canada

Factors Contributing to Annual Hospitality Revenue Variance

Favourable

Revenue contribution from the Hilton Suites Hotel for a full year in 2012 and from the StationPark Hotel for the fourth quarter of 2012

Higher revenue from operations in western Canada

Unfavourable

Lower revenue from operations in central Canada and Atlantic Canada

Factors Contributing to Annual Earnings Variance

Unfavourable

Lower performance at the Hospitality Division, excluding the Hilton Suites Hotel, primarily due to the impact of decreased occupancy at hotel operations in central Canada and Atlantic Canada, partially offset by the impact of increased average room rates and occupancy in western Canada

Increased operating expenses, primarily due to a $3 million non-recurring provision recognized in the fourth quarter of 2012 associated with the Corporation's investment in CWLP

Lower effective income tax recoveries, due to higher Part VI.1 taxes, partially offset by the release of income tax provisions at FortisBC Holdings Inc. ("FHI") in 2012

Higher preference share dividends, due to the issuance of First Preference Shares, Series J in November 2012

Favourable

Increased other income, net of expenses, primarily due to a foreign exchange gain of approximately $1 million recognized in the fourth quarter of 2012 compared to a net foreign exchange loss of $0.5 million ($1 million after tax) recognized in the same quarter last year, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity

Lower finance charges, primarily due to higher capitalized interest associated with the financing of the construction of the Corporation's 51% controlling ownership interest in the Waneta Expansion and the impact of the conversion of the Corporation's US$40 million convertible debentures into common shares in November 2011. The above items were partially offset by higher interest on credit facility borrowings, due to higher average credit facility borrowings.

Factors Contributing to Annual

Net Corporate and Other Expenses Variance

Unfavourable

Increased other expenses, net of other income, primarily due to: (i) the favourable impact in 2011 of the $17 million (US$17.5 million) ($11 million after-tax) fee paid to Fortis in July 2011 following the termination of a Merger Agreement between Fortis and CVPS; (ii) approximately $9 million ($7.5 million after tax) of costs, incurred largely in the first half of 2012, related to the pending acquisition of CH Energy Group; and (iii) a foreign exchange loss of approximately $2 million recognized in 2012 compared to a net foreign exchange gain of approximately $1 million ($1.5 million after tax) recognized in 2011, associated with the translation of the US dollar-denominated long-term other asset representing the book value of the Corporation's expropriated investment in Belize Electricity

Increased operating expenses, for the reason as discussed above for the quarter, as well as increased employee compensation-related expenses

Excluding income tax expense associated with the merger termination fee paid to Fortis in July 2011, effective income tax recoveries decreased, primarily due to the same reason discussed above for the quarter

Higher preference share dividends, for the same reason discussed above for the quarter

Favourable

Lower finance charges, for the same reasons discussed above for the quarter. However, higher fees associated with the increase in the Corporation's committed revolving credit facility to $1 billion in May 2012 had an unfavourable impact on finance charges year over year.

REGULATORY HIGHLIGHTS

The following provides an update on material regulatory decisions and applications associated with the Corporation's regulated gas and electric utilities from that disclosed in the interim MD&A for the three and nine months ended September 30, 2012.

MATERIAL REGULATORY DECISIONS AND APPLICATIONS

Regulated Utility

Summary Description

FEI/FEVI/FEWI

- Following the announcement by the Government of British Columbia of the Greenhouse Gas Reductions (Clean Energy Regulation) ("GHG Regulation") under the Clean Energy Act, which was promulgated in May 2012, FEI announced an incentive funding program to assist eligible vehicle operators in purchasing liquefied natural gas ("LNG")-fuelled vehicles. The incentive program funding includes up to $62 million, over a period of several years, to offset a percentage of the incremental capital cost for eligible operators in purchasing qualifying LNG-fuelled vehicles. The eligible applicants for the incentive program are commercial return-to-base fleet operators of heavy-duty trucks, buses, vocational vehicles and marine vessels. Awarding of the incentives commenced in late 2012 and will cover up to 75% of the eligible operators' incremental capital costs. Additionally, the GHG Regulation allows FEI to invest up to $30 million for LNG fuelling stations and up to $12 million for compressed natural gas ("CNG") fuelling stations. In October 2012 the BCUC approved the rate treatment of the above expenditures being made under the GHG Regulation.

- In December 2012 the British Columbia Utilities Commission ("BCUC") issued its decision regarding the BCUC-initiated public process, which commenced in May 2011, inquiring into whether FEI should be able to provide alternative energy services as regulated utility services and to establish guidelines that would apply to the provision of such services. The BCUC determined that CNG and LNG refuelling services are regulated when they are provided by a public utility such as FEI. The BCUC recommended, however, that FEI undertake such services in the future through a separate non-regulated affiliate, with the exception of expenditures permitted under the GHG Regulation in British Columbia. Similarly, the BCUC determined that biomethane services are part of FEI's regulated service offering, but that ownership of any biogas upgrading systems will be determined on a case by case basis. Moreover, district energy systems and other geo-exchange systems are regulated, and should continue to be carried out through FEI's affiliate, FortisBC Alternative Energy Services Inc. ("FAES"), although an exemption from regulation can be sought for discrete energy systems. FEI is considering the findings of the decision and its impact on its provision of alternative energy services.

- A public oral hearing for the first phase of a Generic Cost of Capital ("GCOC") Proceeding in British Columbia occurred in December 2012. The BCUC has determined that a second, subsequent phase be added to the GCOC Proceeding to determine an appropriate allowed ROE and capital structure for all other regulated utilities in British Columbia once the benchmark utility has been established in the first phase of the GCOC Proceeding. FEI has been designated as the benchmark utility. FEVI, FEWI and FortisBC Electric will have their allowed ROEs and capital structures determined in the second phase of the GCOC Proceeding. A decision on the benchmark utility, FEI, is expected mid-2013. Effective January 1, 2013, as ordered by the BCUC in December 2012, the current allowed ROE and capital structure for FEI and all other regulated entities in British Columbia that rely on the benchmark utility to establish rates are to be maintained and made interim. The results of the GCOC Proceeding could materially impact the earnings of the FortisBC Energy companies and FortisBC Electric.

- FAES has filed applications for approval of various thermal-energy projects. These projects and their status are as follows: (i) Delta School District - approval has been granted by the BCUC; (ii) Tsawwassen Springs Development - approval has been granted by the BCUC; (iii) PCI Marine Gateway - approval has been granted by the BCUC for the capital expenditures, but approval of revisions to the rate design and rates are pending; (iv) Telus Garden - a BCUC decision is expected in early 2013; and (v) Kelowna District Energy System - the regulatory process is ongoing and a BCUC decision is expected in the second quarter of 2013.

FortisBC Electric

- In November 2012 FortisBC Electric filed an application with the BCUC requesting approval for FortisBC Electric to acquire the City of Kelowna's electrical utility assets and to include the assets in FortisBC Electric's rate base.

FortisAlberta

- In September 2012 the AUC issued a generic PBR Decision outlying the PBR framework applicable to distribution utilities in Alberta, including FortisAlberta, for a five-year term commencing January 1, 2013. In the PBR Decision, a formula that estimates inflation annually and assumes productivity improvements is to be used by the distribution utilities to determine customer rates on an annual basis. The PBR Decision raises concerns and uncertainties for FortisAlberta regarding the treatment of certain capital expenditures. While the PBR Decision did provide for a capital tracker mechanism for the recovery of certain capital expenditures, FortisAlberta sought further clarification regarding this mechanism in its required Compliance Application filed in November 2012 and a Review and Variance Application currently before the AUC. FortisAlberta has also sought leave to appeal the issue to the Alberta Court of Appeal. In December 2012 FortisAlberta filed a 2013 Capital Tracker Application with the AUC for specific categories of capital expenditures. A decision on the Compliance Application is expected in the first quarter of 2013. Decisions on the Review and Variance and Capital Tracker Applications are expected in the third quarter of 2013. The outcome of the outstanding applications, including the impact on financial results, if any, and the timing of recognition of such financial results are currently unknown. However, the implementation of PBR does not alter a utility's right to a reasonable opportunity to recover prudent COS and the right to earn a reasonable ROE.

- In its Compliance Application, FortisAlberta requested a 1.71% increase in customer distribution rates, effective January 1, 2013, reflecting the determination of the inflationary and productivity factors in accordance with the PBR Decision. FortisAlberta also requested customer distribution rate adjustments for flow-through costs and transitional adjustments. In December 2012 the AUC issued a decision setting 2012 customer distribution rates as interim rates for 2013, pending AUC decisions on FortisAlberta's Compliance and Capital Tracker Applications.

- In October 2012 the AUC initiated a GCOC Proceeding, which includes the determination of: (i) the allowed ROE for 2013; (ii) whether a formulaic ROE automatic mechanism should be re-established; and (iii) whether the PBR Decision or other decisions require the adjustment of the allowed ROE or equity component of total capital structure as a result of any changes in risk.

- In November 2012 the AUC reinitiated a Utility Asset Disposition ("UAD") Proceeding which will address, among other things, cost responsibility for stranded assets. FortisAlberta is fully participating in the UAD Proceeding and common-utility evidence has been filed and experts have been engaged. The UAD Proceeding is expected to continue through the first quarter of 2013 with a decision expected by the second quarter of 2013. Any decision by the AUC regarding the treatment of stranded assets does not alter a utility's right to a reasonable opportunity to recover prudent COS and the right to earn a reasonable ROE.

- In June 2012 AESO filed with the AUC a Customer Contribution Policy Application and an Amortized Construction Contribution Rider I Application. The first application proposed a reduction in the level of AESO contributions that transmission customers, including FortisAlberta, would pay versus what the transmission facility owner would pay. The second application proposed that transmission customers be given the option to make the required AESO contributions as a series of payments over a number of years, rather than as an up-front payment. Effectively, this would result in the transmission facility owner financing the AESO contributions. In December 2012 the AUC issued a decision that denied both applications and directed AESO to bring forward its proposals as part of its next comprehensive AESO tariff application. As a result, the current contribution policy and the manner in which contributions are paid remain in effect.

- In January 2013 the Government of Alberta responded to the recommendations of the Retail Market Review Committee and, as part of that response, requested that the AUC begin the process to remove the electricity rate increase limitations that have been in effect since February 2012. As the AUC proceeds with the process of removing the electricity rate increase limitations, it is expected that FortisAlberta's interim 2013 customer distribution rates will be adjusted to reflect the AUC's rulings with respect to the Company's Compliance and Capital Tracker Applications.

Newfoundland Power

- In September 2012 Newfoundland Power filed a 2013/2014 General Rate Application for the purpose of setting customer electricity rates and cost of capital. Newfoundland Power is proposing an overall average increase in customer electricity rates of 6%, effective March 1, 2013. The Company is also proposing the discontinuance of the ROE automatic adjustment formula. A public hearing on the application is expected to conclude in February 2013.

Maritime Electric

- In February 2012 the PEI Energy Commission ("PEI Commission") released its Discussion Paper, Charting Our Electricity Future, which outlined discussion points on which the PEI Commission should seek input through a consultative process with stakeholders and the general public. Maritime Electric participated in public forums and stakeholder consultations held in early 2012. In January 2013 the PEI Commission released a Final Report of its recommendations to the Government of PEI, which included the following: (i) Maritime Electric should continue as PEI's primary electric utility; however, the PEI Energy Corporation should acquire Maritime Electric's generation assets over a reasonable period of time, thereby reducing the utility's rate base and equity; (ii) the equity component of Maritime Electric's capital structure should be maintained at no less than 35% and no more than 40% of total capital structure; (iii) the current COS regulatory model should be maintained but responsibility for the Electric Power Act (PEI) should be assigned to a new three-person panel of commissioners that deals only with electric utility regulation and oversight and will operate independently of the Island Regulatory Appeals Commission; (iv) a consumer advocate for electricity should be appointed to better facilitate the participation of interested parties at regulatory hearings; (v) the Government of PEI should assume the responsibility for financing the existing $47.5 million of deferred incremental replacement energy costs at Maritime Electric associated with the refurbishment of the New Brunswick Power Point Lepreau nuclear generating station ("Point Lepreau"); (vi) a new cable interconnection with New Brunswick should be pursued immediately and ownership of the cable should reside with the Government of PEI; and (vii) responsibility for demand-side management programming, currently with the Government of PEI, should transfer back to Maritime Electric.

- In December 2012 the Electric Power (Energy Accord Continuation) Amendment Act (PEI) ("Accord Continuation Act") was enacted which sets out the inputs, rates and other terms for the continuation of the PEI Energy Accord ("Accord") for an additional three years covering the period March 1, 2013 through February 29, 2016. Over the three-year period, increases in electricity costs for a typical residential customer have been set at 2.2% annually and Maritime Electric's allowed ROE has been capped at 9.75% each year. Under the terms of the Accord Continuation Act and the Accord, the Government of PEI assumed responsibility, effective March 1, 2011, for the cost of incremental replacement energy and monthly operating and maintenance costs related to Point Lepreau during its refurbishment period, which ended in fall 2012.

- In December 2012 Maritime Electric's 2013 Capital Budget Application totaling approximately $26 million, before customer contributions, was approved, as filed, with the exception of approximately $1 million related to preparatory work for a third submarine-cable interconnection, which has been deferred for additional consideration by the regulator.

FortisOntario

- In November 2012 the Ontario Energy Board approved, as filed, a settlement agreement pertaining to FortisOntario's COS Application for electricity distribution rates in Fort Erie, Port Colborne and Gananoque, effective January 1, 2013, using a 2013 forward test year. The allowed ROE for 2013, as determined under the ROE automatic adjustment formula, has been calculated at 8.93%, down from the 9.12% that was estimated in the COS Application. In November 2012 the OEB also determined that most of a $1 million income tax-related regulatory deferral is not required to be dispersed to customers. The result of the above decisions, including the impact of the decrease in the allowed ROE effective January 1, 2013, was an average 6.8% increase in residential customer rates in Fort Erie; an average 5.9% increase in residential customer rates in Gananoque; and an average 7.4% increase in residential customer rates in Port Colborne.

- In October 2012 Algoma Power filed a Third-Generation Incentive Rate Mechanism application for customer electricity distribution rates effective January 1, 2013. The application was prepared in a manner consistent with the OEB's decision on the utility's 2012 rate application; however, the 2013 rate application has been complicated by the requirement to dispose of smart meter costs. Since distribution rates for Algoma Power's residential customers are governed by separate regulation, recovery of smart meter investments will impact the determination of Rural and Remote Rate Protection Program funding for 2013. The OEB has scheduled a written hearing for the application.

- In December 2012 the OEB issued an order making Algoma Power's customer rates for 2012 interim rates for 2013, until a final rate order is issued on 2013 customer rates.

Fortis Turks and Caicos

- Negotiations between Fortis Turks and Caicos and the Interim Government of the Turks and Caicos Islands ("Interim Government") occurred during the third quarter of 2012 with Fortis Turks and Caicos presenting a new regulatory framework proposal to the Interim Government. A third-party consultant was engaged by the Interim Government to review the proposal and provide recommendations. No agreement was reached with the Interim Government; however, management expects to continue dialogue on regulatory reform with the newly elected government.

LIQUIDITY AND CAPITAL RESOURCES

The table below outlines the Corporation's consolidated sources and uses of cash for the fourth quarter and year ended December 31, 2012, as compared to the same periods in 2011, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows (Unaudited)

Periods Ended December 31

Quarter

Annual

($ millions)

2012

2011

Variance

2012

2011

Variance

Cash, Beginning of Period

147

106

41

87

107

(20

)

Cash Provided by (Used in):

Operating Activities

172

230

(58

)

976

915

61

Investing Activities

(319

)

(367

)

48

(1,080

)

(1,115

)

35

Financing Activities

154

118

36

171

180

(9

)

Cash, End of Period

154

87

67

154

87

67

Operating Activities: Cash flow from operating activities was $58 million lower quarter over quarter. The decrease was mainly due to unfavourable changes in working capital at the FortisBC Energy companies and FortisAlberta. The unfavourable changes in working capital were associated with current regulatory deferral accounts and inventories. The above decrease was partially offset by favourable changes in long-term regulatory deferral accounts, higher earnings and the collection from customers of regulator-approved increased depreciation and amortization expense.

Cash flow from operating activities was $61 million higher year over year. The increase was primarily due to higher earnings and the collection from customers of regulator-approved increased depreciation and amortization expense, partially offset by unfavourable changes in working capital. The unfavourable changes in working capital were associated with inventories, accounts payable and other current liabilities, and current regulatory deferral accounts, partially offset by favourable changes in accounts receivable.

Investing Activities: Cash used in investing activities was $48 million lower for the quarter and $35 million lower for the year. The decreases were mainly due to: (i) a $49 million deferred payment made in December 2011 in accordance with an agreement, associated with FHI's acquisition of FEVI in 2002, which increased cash used in investing activities in 2011; (ii) a decrease in capital spending; and (iii) a decrease in cash used for business acquisitions. The decrease in capital spending for the quarter was mainly due to the timing of AESO transmission-related capital projects at FortisAlberta. The decrease in capital spending for the year was mainly due to the completion of the Customer Care Enhancement Project at FEVI in early 2012, a delay in capital spending in 2012 at FortisBC Electric, due to the timing of receipt of approval for its 2012/2013 revenue requirements, and the expropriation of Belize Electricity and the resulting discontinuance of the consolidation method of accounting for the utility, effective June 20, 2011. The above decreases for the year were partially offset by higher capital spending at FortisAlberta, due to the connection of new customers driven by strong economic growth in Alberta, and increased capital spending related to the Waneta Expansion. The decrease in cash used in business acquisitions was the result of the acquisition of the Hilton Suites Hotel in October 2011 for $25 million, compared to: (i) the acquisition of the StationPark Hotel in October 2012 for $7 million, net of debt assumed; (ii) the acquisition of TCU in August 2012 for $8 million (US$8 million), net of debt assumed; and (iii) the acquisition of the electricity distribution assets from the City of Port Colborne in April 2012 for $7 million. The above decreases in cash used in investing activities were partially offset by lower proceeds from the sale of utility capital assets. In October 2011 Newfoundland Power sold joint-use poles and related infrastructure to Bell Aliant for $45 million, net of costs.

Cash provided by financing activities was $9 million lower year over year, mainly due to: (i) lower proceeds from the issuance of common shares; (ii) lower proceeds from long-term debt; (iii) higher repayments of long-term debt; (iv) higher common share dividends; and (v) costs related to the issuance of Subscription Receipts in June 2012. The above items were partially offset by: (i) higher net borrowings under committed credit facilities classified as long term; (ii) proceeds from the issuance of preference shares in November 2012; (iii) lower net repayments of short-term borrowings; and (iv) higher advances from non-controlling interests in the Waneta Partnership.

In November 2012 Fortis completed a $200 million public offering of 8 million First Preference Shares, Series J. The net proceeds of approximately $194 million were used to repay borrowings under the Corporation's committed corporate credit facility, which borrowings were primarily incurred to support the construction of the Waneta Expansion and for other general corporate purposes.

Mid-2011 Fortis publicly issued 10.3 million common shares for $341 million. The net proceeds of $327 million were largely used to repay borrowings under credit facilities and support the construction of the Waneta Expansion and for other general corporate purposes.

CAPITAL STRUCTURE

The consolidated capital structure of Fortis is presented in the following table.

Capital Structure (Unaudited)

As at

December 31, 2012

December 31, 2011

($ millions)

(%)

($ millions)

(%)

Total debt and capital lease and finance obligations (net of cash) (1)

6,317

55.3

6,296

57.1

Preference shares

1,108

9.7

912

8.3

Common shareholders' equity

3,992

35.0

3,823

34.6

Total (2)

11,417

100.0

11,031

100.0

(1)

Includes long-term debt and capital lease and finance obligations, including current portion, and short-term borrowings, net of cash

(2)

Excludes amounts related to non-controlling interests

The improvement in the capital structure was primarily due to: (i) the First Preference Shares, Series J offering in November 2012 for net proceeds of approximately $194 million, which were used to repay borrowings under the Corporation's committed corporate credit facility; (ii) common shares issued under the Corporation's dividend reinvestment and stock option plans; (iii) net earnings attributable to common equity shareholders, net of dividends; and (iv) an increase in cash. The capital structure was also impacted by an increase in long-term debt, largely in support of energy infrastructure investment.

In May 2012 and July 2012, S&P and DBRS, respectively, affirmed the Corporation's debt credit ratings. Due to the Corporation's financing plans for the pending acquisition of CH Energy Group and the expected completion of the Waneta Expansion on time and on budget, S&P and DBRS also removed the ratings from credit watch with negative implications and under review with developing implications, respectively, where the ratings had been placed in February 2012.

CAPITAL EXPENDITURE PROGRAM

Capital investment in infrastructure is required to ensure continued and enhanced performance, reliability and safety of the gas and electricity systems and to meet customer growth. All costs considered to be maintenance and repairs are expensed as incurred. Costs related to replacements, upgrades and betterments of capital assets are capitalized as incurred.

A breakdown of the approximate $1.1 billion in gross capital expenditures by segment for 2012 is provided in the following table.

Gross Consolidated Capital Expenditures (Unaudited) (1)

Year Ended December 31, 2012

($ millions)

FortisBC
Energy
Companies

Fortis
Alberta

FortisBC
Electric

Newfoundland
Power

Other
Regulated
Electric
Utilities
-
Canadian

TotalRegulatedUtilities
-Canadian

RegulatedElectricUtilities
-Caribbean

Non-Regulated
-FortisGeneration

Non-Regulated
-FortisProperties

Total

206

442

69

86

48

851

48

196

35

1,130

(1)

Relates to cash payments to acquire or construct utility capital assets, income-producing properties and intangible assets, as reflected on the consolidated statement of cash flows. Excludes capitalized depreciation and amortization and non-cash equity component of AFUDC.

Gross consolidated capital expenditures of $1,130 million for 2012 were $161 million lower than $1,291 million forecasted for 2012, as disclosed in the MD&A for the year ended December 31, 2011. Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from forecasts. Lower-than-forecasted capital spending was mainly due to: (i) a shift in capital expenditures from 2012 to 2013 related to the timing of payments associated with the Waneta Expansion; (ii) a delay in capital spending at FortisBC Electric and the FortisBC Energy companies, due to the timing of receipt of regulatory approvals for their 2012/2013 revenue requirements; and (iii) timing of capital spending associated with the construction of Fortis Properties' office building in St. John's, Newfoundland. The above decreases were partially offset by higher-than-forecasted capital spending at FortisAlberta, due to higher spending associated with customers in the oil and gas sectors and capital expenditures associated with a distribution control centre, partially offset by lower-than-forecasted AESO transmission-related capital expenditures.

An update on larger capital projects for 2012 from that disclosed in the MD&A as at December 31, 2011 is provided below.

FEI's Customer Care Enhancement Project came into service at the beginning of 2012 at a total project cost of approximately $110 million.

During 2012 FortisAlberta continued with the replacement of vintage poles under its Pole-Management Program, which involves approximately 110,000 poles in total, to prevent risk of failure due to age. The total capital cost of the program through 2019 is now expected to be approximately $327 million, compared to $335 million forecasted as at December 31, 2011. Approximately $27 million was spent on this program in 2012.

The Environmental Compliance Project at FortisBC Electric relates to work required to ensure compliance of the utility's substation equipment with the Canadian Environmental Protection Act PCB Regulations by 2014. The project has been approved by the regulator and is estimated to cost approximately $28 million through 2014. Approximately $6 million has been spent on this project to the end of 2012.

Construction progress on the $900 million, 335-MW Waneta Expansion is going well and the project is currently on schedule and on budget. Major construction activities on-site during 2012 included the completion of the excavation of the intake, powerhouse and power tunnels. Approximately $436 million in total has been spent on the Waneta Expansion since construction began in late 2010, with $192 million spent in 2012.

Fortis Properties is constructing a 12-storey office building in downtown St. John's, Newfoundland at an estimated cost of approximately $47 million. Approximately $20 million has been spent on this project to the end of 2012. Construction is expected to be completed by the end of 2013.

Over the five-year period 2013 through 2017, consolidated gross capital expenditures, including expenditures at Central Hudson, are expected to be approximately $6 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 59% at the Canadian regulated electric utilities, driven by FortisAlberta; 19% at the regulated gas utilities; 11% at Central Hudson; and the remaining 11% at non-regulated operations. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, on average annually, the approximate breakdown of the utility capital spending to be incurred is as follows: 38% to meet customer growth; 43% to ensure continued and enhanced performance, reliability and safety of generation and T&D assets, i.e., sustaining capital expenditures; and 19% for facilities, equipment, vehicles, information technology and other assets.

Gross consolidated capital expenditures for 2013, excluding capital expenditures at Central Hudson, are expected to be approximately $1.3 billion. Central Hudson's capital program over the next five years is expected to average more than $125 million annually.

A breakdown of forecast gross consolidated capital expenditures by segment for 2013 is provided in the following table.

Forecast Gross Consolidated Capital Expenditures (1)

Year Ending December 31, 2013

($ millions)

FortisBC
Energy
Companies

Fortis
Alberta

FortisBC
Electric

Newfoundland
Power

Other
Regulated
Electric
Utilities
-
Canadian

TotalRegulatedUtilities
-Canadian

RegulatedElectricUtilities
-Caribbean

Non-Regulated
-FortisGeneration

FortisPropertiesand Other (2)

Total

229

437

133

86

54

939

69

229

113

1,350

(1)

Relates to forecasted cash payments to acquire or construct utility capital assets, income producing properties and intangible assets, as would be reflected on the consolidated statement of cash flows. Excludes forecasted capitalized depreciation and amortization and non-cash equity component of AFUDC.

(2)

Includes forecasted capital expenditures of approximately $70 million at Fortis Properties and approximately $43 million at FAES, which is currently reported in the Corporate and Other segment. For further information refer to the "Material Regulatory Decisions and Applications" section of this earnings release.

The most significant capital project for 2013 is the continuation of the construction of the non-regulated Waneta Expansion, with approximately $227 million expected to be spent in 2013. Key project activities for 2013 include completion of the powerhouse structural steel and building envelope; excavation of the intake approach channel; construction of the intake and tailrace structures; and removal of rock plug. In addition, installation of the stationary imbedded turbine and generator components will continue.

CREDIT FACILITIES

As at December 31, 2012, the Corporation and its subsidiaries had consolidated credit facilities of approximately $2.5 billion, of which $2.1 billion was unused, including $946 million unused under the Corporation's $1 billion committed revolving corporate credit facility. The credit facilities are syndicated almost entirely with the seven largest Canadian banks, with no one bank holding more than 20% of these facilities. Approximately $2.3 billion of the total credit facilities are committed facilities with maturities ranging from 2013 to 2017.

The following table outlines the credit facilities of the Corporation and its subsidiaries.

Credit Facilities (Unaudited)

As at

Regulated

Fortis

Corporate

December 31,

December 31,

($ millions)

Utilities

Properties

and Other

2012

2011

Total credit facilities

1,402

13

1,045

2,460

2,248

Credit facilities utilized:

Short-term borrowings

(136

)

-

-

(136

)

(159

)

Long-term debt (including current portion)

(97

)

-

(53

)

(150

)

(74

)

Letters of credit outstanding

(66

)

-

(1

)

(67

)

(66

)

Credit facilities unused

1,103

13

991

2,107

1,949

OUTLOOK

Over the five years 2013 through 2017, the Corporation's capital program, including expenditures at Central Hudson, is expected to total approximately $6 billion, and will support continuing growth in earnings and dividends. Capital investment over that period is expected to allow utility rate base and hydroelectric generation investment to increase at a combined compound annual growth rate of approximately 6%.

Approval by the NYSPSC of the Corporation's acquisition of CH Energy Group is the last significant regulatory matter required to close the transaction. The acquisition is anticipated to close during the second quarter of 2013. With the acquisition of CH Energy Group, the Corporation's regulated midyear rate base will increase to approximately $10 billion.

Fortis is focused on closing the CH Energy Group acquisition. Fortis also remains disciplined and patient in its pursuit of additional electric and gas utility acquisitions in the United States and Canada that will add value for Fortis shareholders. Fortis will also pursue growth in its non-regulated businesses in support of its regulated utility growth strategy.

FORTIS INC.

Consolidated Financial Statements

As at and for the three and twelve months ended December 31, 2012 and 2011

(Unaudited)

Prepared in accordance with accounting principles generally accepted in the United States

Fortis Inc.

Consolidated Balance Sheets (Unaudited)

As at December 31

(in millions of Canadian dollars)

2012

2011

ASSETS

Current assets

Cash and cash equivalents

$

154

$

87

Accounts receivable

587

638

Prepaid expenses

18

19

Inventories

133

134

Regulatory assets

185

230

Deferred income taxes

16

24

1,093

1,132

Other assets

200

184

Regulatory assets

1,515

1,388

Deferred income taxes

-

8

Utility capital assets

9,623

9,018

Income producing properties

626

594

Intangible assets

325

325

Goodwill

1,568

1,565

$

14,950

$

14,214

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities

Short-term borrowings

$

136

$

159

Accounts payable and other current liabilities

966

977

Regulatory liabilities

72

51

Current installments of long-term debt

117

103

Current installments of capital lease and finance obligations

7

7

Deferred income taxes

10

8

1,308

1,305

Other liabilities

622

564

Regulatory liabilities

681

612

Deferred income taxes

718

676

Long-term debt

5,783

5,685

Capital lease and finance obligations

428

429

9,540

9,271

Shareholders' equity

Common shares (1)

3,121

3,036

Preference shares

1,108

912

Additional paid-in capital

15

14

Accumulated other comprehensive loss

(96

)

(95

)

Retained earnings

952

868

5,100

4,735

Non-controlling interests

310

208

5,410

4,943

$

14,950

$

14,214

(1)

no par value: unlimited authorized shares; 191.6 million and 188.8 million issued and outstanding as at December 31, 2012 and 2011, respectively

Proceeds on sale of utility capital assets and income producing properties

3

45

3

51

Business acquisitions, net of cash acquired

(7

)

(25

)

(21

)

(25

)

(319

)

(367

)

(1,080

)

(1,115

)

Financing activities

Change in short-term borrowings

39

(84

)

(22

)

(198

)

Proceeds from long-term debt, net of issue costs

124

304

124

343

Repayments of long-term debt and capital lease and finance obligations

(31

)

(13

)

(88

)

(40

)

Net (repayments) borrowings under committed credit facilities

(150

)

(40

)

71

(145

)

Advances from non-controlling interests

23

4

106

81

Subscription Receipts issue costs

-

-

(13

)

-

Issue of common shares, net of costs and dividends reinvested

12

4

24

345

Issue of preference shares, net of costs

194

-

194

-

Dividends

Common shares, net of dividends reinvested

(42

)

(42

)

(170

)

(151

)

Preference shares

(12

)

(12

)

(46

)

(46

)

Subsidiary dividends paid to non-controlling interests

(3

)

(3

)

(9

)

(9

)

154

118

171

180

Change in cash and cash equivalents

7

(19

)

67

(20

)

Cash and cash equivalents, beginning of period

147

106

87

107

Cash and cash equivalents, end of period

$

154

$

87

$

154

$

87

Fortis Inc.

Consolidated Statements of Changes in Equity (Unaudited)

For the periods ended December 31

(in millions of Canadian dollars)

Com-
mon
Shares

Prefe-
rence
Shares

Addi-
tional
Paid-inCapital

Accu-
mulated
OtherCompre-
hensiveLoss

Retained
Earnings

Non-
Control-
ling
Interests

Total
Equity

As at January 1, 2012

$

3,036

$

912

$

14

$

(95

)

$

868

$

208

$

4,943

Net earnings

-

-

-

-

362

9

371

Other comprehensive loss

-

-

-

(1

)

-

-

(1

)

Preference share issue

-

196

-

-

-

-

196

Common share issues

85

-

(3

)

-

-

-

82

Stock-based compensation

-

-

4

-

-

-

4

Advances from non-controlling interests

-

-

-

-

-

106

106

Foreign currency translation impacts

-

-

-

-

-

(4

)

(4

)

Subsidiary dividends paid to non-controlling interests

-

-

-

-

-

(9

)

(9

)

Dividends declared on common shares ($1.21 per share)

-

-

-

-

(231

)

-

(231

)

Dividends declared on preference shares

-

-

-

-

(47

)

-

(47

)

As at December 31, 2012

$

3,121

$

1,108

$

15

$

(96

)

$

952

$

310

$

5,410

As at January 1, 2011

$

2,575

$

912

$

12

$

(108

)

$

774

$

162

$

4,327

Net earnings

-

-

-

-

357

9

366

Other comprehensive income

-

-

-

13

-

-

13

Common share issues

461

-

(2

)

-

-

-

459

Stock-based compensation

-

-

4

-

-

-

4

Advances from non-controlling interests

-

-

-

-

-

81

81

Foreign currency translation impacts

-

-

-

-

-

3

3

Subsidiary dividends paid to non-controlling interests

-

-

-

-

-

(9

)

(9

)

Expropriation of Belize Electricity

-

-

-

-

-

(38

)

(38

)

Dividends declared on common shares ($1.17 per share)

-

-

-

-

(217

)

-

(217

)

Dividends declared on preference shares

-

-

-

-

(46

)

-

(46

)

As at December 31, 2011

$

3,036

$

912

$

14

$

(95

)

$

868

$

208

$

4,943

SEGMENTED INFORMATION (Unaudited)

Information by reportable segment is as follows:

REGULATED

NON-REGULATED

Gas Utilities

Electric Utilities

Quarter EndedDecember 31, 2012($ millions)

FortisBC EnergyCompanies
-Canadian

Fortis
Alberta

FortisBC
Electric

New-found-
land
Power

Other
Canadian

TotalElectricCanadian

ElectricCaribbean

FortisGeneration

FortisProperties

Corporateand Other

Inter-segmenteliminations

Consolidated

Revenue

422

113

81

159

89

442

71

5

61

6

(8

)

999

Energy supply costs

197

-

22

106

59

187

46

-

-

-

-

430

Operating expenses

90

42

23

20

13

98

10

3

42

6

(2

)

247

Depreciation and amortization

40

34

12

11

6

63

8

1

6

1

-

119

Operating income

95

37

24

22

11

94

7

1

13

(1

)

(6

)

203

Other income, net

-

2

-

-

-

2

-

2

-

2

-

6

Finance charges

35

16

10

9

5

40

3

1

6

11

(6

)

90

Income tax expense (recovery)

11

-

2

3

-

5

-

-

2

(1

)

-

17

Net earnings (loss)

49

23

12

10

6

51

4

2

5

(9

)

-

102

Non-controlling interests

-

-

-

1

-

1

1

-

-

-

-

2

Preference share dividends

-

-

-

-

-

-

-

-

-

13

-

13

Net earnings (loss) attributable to common equity shareholders

49

23

12

9

6

50

3

2

5

(22

)

-

87

Goodwill

913

227

221

-

67

515

140

-

-

-

-

1,568

Identifiable assets

4,595

2,776

1,705

1,389

720

6,590

740

737

655

511

(446

)

13,382

Total assets

5,508

3,003

1,926

1,389

787

7,105

880

737

655

511

(446

)

14,950

Gross capital expenditures (1)

62

138

17

28

13

196

15

52

11

-

-

336

Quarter Ended

December 31, 2011

($ millions)

Revenue

476

102

81

156

83

422

71

9

58

6

(8

)

1,034

Energy supply costs

264

-

23

103

55

181

46

-

-

-

(1

)

490

Operating expenses

84

38

25

21

14

98

9

2

39

2

(1

)

233

Depreciation and amortization

30

34

11

10

6

61

9

1

5

1

-

107

Operating income

98

30

22

22

8

82

7

6

14

3

(6

)

204

Other income, net

2

2

-

-

-

2

1

-

-

1

-

6

Finance charges

33

16

10

9

4

39

3

-

6

13

(6

)

88

Income tax expense (recovery)

16

-

2

4

2

8

-

1

3

(2

)

-

26

Net earnings (loss)

51

16

10

9

2

37

5

5

5

(7

)

-

96

Non-controlling interests

-

-

-

1

-

1

1

-

-

-

-

2

Preference share dividends

-

-

-

-

-

-

-

-

-

12

-

12

Net earnings (loss) attributable to common equity shareholders

51

16

10

8

2

36

4

5

5

(19

)

-

82

Goodwill

913

227

221

-

63

511

141

-

-

-

-

1,565

Identifiable assets

4,579

2,483

1,665

1,299

670

6,117

719

546

610

469

(391

)

12,649

Total assets

5,492

2,710

1,886

1,299

733

6,628

860

546

610

469

(391

)

14,214

Gross capital expenditures (1)

73

163

24

26

14

227

14

43

10

-

-

367

(1)

Relates to cash payments to acquire or construct utility capital assets, income-producing properties and intangible assets, as reflected on the consolidated statements of cash flows

REGULATED

NON-REGULATED

Gas Utilities

Electric Utilities

Year EndedDecember 31, 2012($ millions)

FortisBC EnergyCompanies
-Canadian

Fortis
Alberta

FortisBC
Electric

New-found-land
Power

Other
Canadian

TotalElectricCanadian

ElectricCaribbean

FortisGeneration

FortisProperties

Corporateand Other

Inter-segmenteliminations

Consolidated

Revenue

1,426

448

306

581

353

1,688

273

31

242

24

(30

)

3,654

Energy supply costs

669

-

76

380

227

683

170

1

-

-

(1

)

1,522

Operating expenses

287

158

85

74

48

365

34

9

166

14

(7

)

868

Depreciation and amortization

160

133

48

44

26

251

32

4

21

2

-

470

Operating income

310

157

97

83

52

389

37

17

55

8

(22

)

794

Other income (expenses), net

2

4

1

2

-

7

2

3

-

(9

)

(1

)

4

Finance charges

142

65

39

36

21

161

13

2

24

47

(23

)

366

Income tax expense (recovery)

31

-

9

11

7

27

-

1

9

(7

)

-

61

Net earnings (loss)

139

96

50

38

24

208

26

17

22

(41

)

-

371

Non-controlling interests

1

-

-

1

-

1

7

-

-

-

-

9

Preference share dividends

-

-

-

-

-

-

-

-

-

47

-

47

Net earnings (loss) attributable to common equity shareholders

138

96

50

37

24

207

19

17

22

(88

)

-

315

Goodwill

913

227

221

-

67

515

140

-

-

-

-

1,568

Identifiable assets

4,595

2,776

1,705

1,389

720

6,590

740

737

655

511

(446

)

13,382

Total assets

5,508

3,003

1,926

1,389

787

7,105

880

737

655

511

(446

)

14,950

Gross capital expenditures (1)

206

442

69

86

48

645

48

196

35

-

-

1,130

Year Ended

December 31, 2011

($ millions)

Revenue

1,566

408

296

573

339

1,616

305

34

231

23

(37

)

3,738

Energy supply costs

854

-

72

369

218

659

192

1

-

-

(9

)

1,697

Operating expenses

293

144

83

75

48

350

40

8

156

9

(6

)

850

Depreciation and amortization

113

134

45

42

24

245

33

4

19

2

-

416

Operating income

306

130

96

87

49

362

40

21

56

12

(22

)

775

Other income, net

8

5

1

-

-

6

3

1

-

21

(1

)

38

Finance charges

137

60

39

36

20

155

14

2

24

54

(23

)

363

Income tax expense (recovery)

40

1

10

18

9

38

1

2

9

(6

)

-

84

Net earnings (loss)

137

74

48

33

20

175

28

18

23

(15

)

-

366

Non-controlling interests

-

-

-

1

-

1

8

-

-

-

-

9

Preference share dividends

-

-

-

-

-

-

-

-

-

46

-

46

Net earnings (loss) attributable to common equity shareholders

137

74

48

32

20

174

20

18

23

(61

)

-

311

Goodwill

913

227

221

-

63

511

141

-

-

-

-

1,565

Identifiable assets

4,579

2,483

1,665

1,299

670

6,117

719

546

610

469

(391

)

12,649

Total assets

5,492

2,710

1,886

1,299

733

6,628

860

546

610

469

(391

)

14,214

Gross capital expenditures (1)

250

416

102

81

47

646

71

174

30

-

-

1,171

(1)

Relates to cash payments to acquire or construct utility capital assets, income-producing properties and intangible assets, as reflected on the consolidated statements of cash flows

CORPORATE INFORMATION

Fortis Inc. is the largest investor-owned distribution utility in Canada, with total assets of approximately $15 billion and fiscal 2012 revenue totalling $3.7 billion. The Corporation serves more than 2 million gas and electricity customers. Its regulated holdings include electric distribution utilities in five Canadian provinces and two Caribbean countries and a natural gas utility in British Columbia. Fortis owns and operates non-regulated generation assets across Canada and in Belize and Upstate New York. It also owns hotels and commercial office and retail space in Canada.

The Common Shares, First Preference Shares, Series C; First Preference Shares, Series E; First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series J; and Subscription Receipts of Fortis are traded on the Toronto Stock Exchange under the symbols FTS, FTS.PR.C, FTS.PR.E, FTS.PR.F, FTS.PR.G, FTS.PR.H, FTS.PR.J and FTS.R, respectively.

Additional information, including the Fortis 2011 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's web site at www.fortisinc.com.